Oil/Water Separation of Full Well Stream By Flocculation-Demulsification Process

ABSTRACT

A process for the separation of production fluids is provided. The production fluids comprise an oil/water emulsion stabilized with fine solids. The emulsion may further comprise asphaltenes and naphthenic acids and resins. The process includes subjecting the emulsion to a flocculating agent to flocculate solids within the emulsion, and separating water and solids from crude oil in a first separator. The process further includes subjecting the separated crude oil to a demulsifier after subjecting the emulsion to a flocculating agent, and further separating water from the crude oil in a second separator. A process for producing fluids from a hydrocarbon-bearing reservoir is also provided, using the separation processes herein.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No.60/838,016, filed 16 Aug. 2006.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to the field of fluid separation. Morespecifically, the present invention relates to the separation of oil andwater in connection with hydrocarbon production activities.

2. Background of the Invention

Effective separation of water from produced crude oil is a continuingneed for the oil industry. Effective separation is particularly usefulduring the early stages of production from a well when there may be highwater content. Even in wells that do not have significant initial waterproduction, water cuts can increase over the life of a well to the pointwhere the production fluids have to be treated to remove water.

When water is produced with oil it is frequently in the form of anemulsion. An emulsion is a heterogeneous liquid system involving twoimmiscible liquids, with one of the liquids being intimately dispersedin the form of droplets in the second liquid. The matrix of an emulsionis called the external or continuous phase, while the portion of theemulsion that is in the form of small droplets is called the internal,dispersed, or discontinuous phase.

The stability of an emulsion is generally controlled by the type andamount of surface-active agents present. In some instances, particularlywith heavy oils, finely divided mineral solids existing within theproduction stream can act as emulsifying agents. The emulsifying agentsform interfacial films around the droplets of the dispersed phase andcreate a barrier that slows down or inhibits coalescence of the waterdroplets.

The tendency of heavy oils to contain water-in-oil emulsions isattributable to the presence of certain hydrocarbon molecules sometimesfound in heavy crudes. Particularly, high naphthenic acid and asphaltenecontent crude oils possess the tendency to form stable, water-in-crudeoil emulsions. The polar naphthenic acids and asphaltenes in crude oilstabilize dispersed water droplets. Further, sub-micron sized solidslike silica and clay, when present in the crude oil, interact with thepolar acids and asphaltenes to enhance the stability of the emulsions.Formation of stable water-in-crude emulsions results in difficulty inseparating water from the crude oil.

For bitumen produced from oil sands, both water and solids result fromthe oil sands extraction process. This means that solids are alsoseparated from the crude oil. Crude oil dehydration treating systems aretypically used to reduce the basic sediment and water (BS&W) out ofcrude oil to the acceptable level specified by a crude oil purchaser,such as a pipeline company. The level of sediment and water typicallyspecified by purchasers is less than 1%.

It has been known to separate water from crude oil using settling tanksand mechanical separators. However, when water forms a stable emulsionwith crude oil, the use of storage or settling tanks and mechanicalseparators may fail to provide the separation desired. Emulsions ofheavy oil and water produced from a reservoir formation can contain fromabout 1% to about 60% water by volume. A common range of emulsifiedwater in crude oils heavier than 20° API is from 10% to 35%.

In an effort to further separate produced water from crude oil, it isalso known to treat the well stream (i.e. the production fluids) withchemicals. These chemicals are referred to as dehydration chemicals ordemulsifiers. Demulsifiers allow the dispersed droplets of the emulsionto coalesce into larger drops and settle out of the matrix. For example,U.S. Pat. No. 5,045,212; U.S. Pat. No. 4,686,066; and U.S. Pat. No.4,160,742 disclose examples of chemical demulsifiers used for breakingemulsions. In addition, commercially available chemical demulsifiers,such as ethoxylated-propoxylated phenolformaldehyde resins andethoxylated-propoxylated alcohols, are known for demulsification ofcrude oils. Such demulsifiers further minimize the amount of heat andsettling time otherwise required for separation. However, theeffectiveness of these demulsifiers on heavy crude oils, particularlythose containing asphaltenes, naphthenic acids and inorganic solids maybe limited.

Where the crude oil is heavy oil, it is typical to also employelectrostatic separators. Gravity settling and centrifugation inconjunction with chemical demulsifiers have also been employed.

It is also a known practice to increase the temperature of operation ofseparators in an attempt to break water/oil emulsions. U.S. Pat. No.4,938,876 (herein referred to as the '876 patent) discloses a method forseparating oil, water and solids from emulsions by heating the emulsionto about 115° C., rapidly cooling the mixture to below 100° C.,separating the solids from the liquids and then separating the waterfrom the oil. The '876 patent describes applying “an effective amount ofa surfactant as a demulsifying agent” before heating. The patent furtherdiscloses the addition of a flocculant prior to cooling the mixture.

In some known technologies for breaking emulsions, an intermediateemulsion rag layer is produced. Further processing of the rag layer maybe utilized to recover the crude oil and discharge the water. Recently,a microwave technology has been disclosed in U.S. Pat. Nos. 6,086,830and 6,077,400. This microwave technology uses microwaves to treathard-to-treat emulsions, especially for the rag layer. Other fluidtreatment processes have been in U.S. Pat. No. 6,189,613 and U.S. Pat.No. 6,491,824.

There remains a need for improved demulsification processes foroil/water emulsions, such as heavy crude oil emulsions and bitumenemulsions. There is also a need for an improved fluid separation processin which a flocculant is applied to the well stream, followed by ademulsification and separation process. A need also exists for improveddemulsification of heavy crude oils stabilized by solids-crude oil polarcomplexes.

SUMMARY OF THE INVENTION

The benefits and advantages of the present invention are achieved by animproved process for oil/water separation of oil well production fluids.The production fluids define an oil/water emulsion stabilized with finesolids. The emulsion may further comprise asphaltenes and naphthenicacids and resins.

Generally, the separation process includes subjecting the emulsion to aflocculating agent to flocculate solids within the emulsion. Theemulsion is then carried through a first separator to separate at leastsome water and solids from the crude oil. The process further includessubjecting the separated crude oil to a demulsifier after subjecting theemulsion to the flocculating agent, and then separating additional waterfrom crude oil in a second separator. The separation process may furtherinclude the step of processing the crude oil released from the secondseparator through a third separator.

Subjecting the emulsion to a flocculating agent may be conducted byinjecting the flocculating agent down the wellbore. In one aspect, theflocculant is further injected into a hydrocarbon-bearing reservoiraround the wellbore. Alternatively, subjecting the emulsion to aflocculating agent may be conducted by mixing the flocculating agentwith the oil/water emulsion at a surface facility. In this instance,separating water and solids from crude oil in a first separator is alsoconducted at the surface facility.

Subjecting the crude oil to a demulsifier may be conducted by mixing ademulsifier into the separated crude oil before the emulsion enters thesecond separator. Alternatively, subjecting the separated crude oil to ademulsifier may be conducted by mixing the demulsifier into the crudeoil within the second separator. Preferably, the temperature ofoperation in the second separator is in a range wherein the demulsifierfunction does not act as a dispersant. In one embodiment, the operatingtemperature of the second separator is between about 25° Celsius (C) andabout 70° C. In another embodiment, the operating temperature of thefirst separator is also between about 25° C. and about 70° C. In oneaspect, the operating pressure of the second separator is betweenambient pressure and about 200 pounds per square inch gauge (psig) or1480.4 kilo Pascal (kPa).

The flocculating agent may be an inorganic salt. For instance, theflocculating agent may be aluminum sulfate, ferric chloride, or mixturesthereof. In another example, the flocculating agent may be a cationicpolymer, an anionic polymer, or mixtures thereof. Preferably, theflocculating agent is delivered by an aqueous delivery medium.

Various dosages of the flocculating agent may be used. For instance,subjecting the emulsion to a flocculating agent may be conducted bymixing the flocculating agent with the oil/water emulsion at the surfacefacility, with the dosage of flocculating agent being between about 5parts per million (ppm) to about 1,000 ppm based on the weight of theemulsion. In another instance, the flocculating agent is delivered intothe wellbore by an aqueous delivery medium, and the dosage offlocculating agent into the wellbore is between about 20 ppm to about2,000 ppm based on the weight of the delivery medium.

Various demulsifiers may be used in different embodiments. In oneaspect, the demulsifier is comprised of one or moreethyleneoxy-propyleneoxy (EO-PO) polymers as a demulsifier activeingredient. In another aspect, the demulsifier is selected fromethoxylated-propoxylated phenolformaldehyde resins andethoxylated-propoxylated alcohols. The demulsifier may be present in therange from about 0.1 weight (wt.) % to about 5.0 wt. % based on theamount of the separated crude oil.

A delivery solvent may also be mixed with the demulsifier beforetreating the separated crude oil. The solvent may be, for instance,crude oil distillates boiling in the range of about 70° C. to about 450°C. The delivery solvent is selected from the group consisting of crudeoil distillates, alcohols, ethers, or mixtures thereof. In oneembodiment, the delivery solvent is present in an amount of from about35 wt. % to about 75 wt. % in the demulsifier, such weight percentagebeing included in the 0.1 wt. % to 5.0 wt. % demulsifier added to theseparated crude oil.

A process for producing fluids from a hydrocarbon-bearing reservoir isalso provided. In one embodiment, the process includes moving productionfluids from the reservoir into a wellbore, the production fluidscomprising a crude oil/water emulsion stabilized at least in part bysolids. From there, the production fluids are moved through the wellboreto a surface facility. The process further includes subjecting theproduction fluids to a flocculating agent to flocculate solids withinthe emulsion, separating water and solids in the emulsion from crude oilin a first separator, subjecting the separated crude oil to ademulsifier after subjecting the emulsion to the flocculating agent, andseparating additional water from crude oil in a second separator. In oneaspect, the method further comprises processing the crude oil releasedfrom the second separator through a third separator.

The second separator operates in a temperature range wherein thedemulsifier does not act as a dispersant. Preferably, the operatingtemperature of the second separator is between about 25° C. and about75° C., or more preferably between about 50° C. and about 70° C.Further, the operating temperature of the second separator may be about15° C. to about 50° C. below an operating temperature of the firstseparator.

In one aspect, subjecting the emulsion to a flocculating agent isconducted by injecting the flocculating agent down a wellbore. Further,separating water and solids from crude oil in a first separator isconducted at a surface facility. Still further, subjecting the emulsionto a flocculating agent is conducted by mixing the flocculating agentwith the oil/water emulsion at the surface facility.

The flocculating agent may be an inorganic salt. The flocculating agentmay be a cationic polymer, an anionic polymer, or mixtures thereof. Inone aspect, subjecting the emulsion to a flocculating agent is conductedby mixing the flocculating agent with the oil/water emulsion at thesurface. In this instance, the dosage of the flocculating agent put intothe wellbore is between about 5 ppm to about 1,000 ppm based on theweight of the emulsion. In another aspect, the flocculating agent isdelivered into the wellbore by an aqueous delivery medium. In thisinstance, the dosage of flocculating agent into the wellbore is betweenabout 20 ppm to about 2,000 ppm based on the weight of the deliverymedium.

In one embodiment, subjecting the crude oil to a demulsifier comprisesmixing a demulsifier into the separated crude oil before the crude oilenters the second separator. The demulsifier may be comprised of one ormore ethyleneoxy-propyleneoxy (EO-PO) polymers as a demulsifier activeingredient. For example, the demulsifier may be selected fromethoxylated-propoxylated phenolformaldehyde resins andethoxylated-propoxylated alcohols. In one aspect, the demulsifier is inthe range from about 0.1 wt. % to about 5.0 wt. % based on the amount ofthe separated crude oil.

The demulsifier may be mixed with a delivery solvent before treating theseparated crude oil. In one aspect, the delivery solvent is present inan amount of from about 35 wt. % to about 75 wt. % in the demulsifier,such weight percentage being included in the 0.1 wt. % to 5.0 wt. %demulsifier added to the separated crude oil.

In any of the methods, the emulsion is typically, though notnecessarily, a water-in-oil emulsion. The oil is typically, though notnecessarily, a heavy oil. The emulsion may contain dissolved inorganicsalts of chloride, sulfates or carbonates of Group I and II elements ofthe long form of The Periodic Table of Elements.

In any of the methods, the stabilizing solids in the emulsion maycomprise at least one of formation fines, drilling muds and completionfluids. For instance, the solids may comprise fine solids with diametersfrom about 0.5 microns to about 100 microns. The solids may comprise atleast one of silica and clay.

In any of the methods, the production fluids may comprise one or more ofasphaltenes, naphthenic acid compounds, resins, and mixtures thereof.

In any of the methods, the separators may be any one of a number ofdifferent types of separators. For instance, the first separator may beat least one of a centrifugation separator, a gravity settlingseparator, a hydrocyclone, a separator that applies an electrostaticfield, and a separator that applies microwave treatment. Similarly, thethird separator may be at least one of a centrifugation separator, agravity settling separator, a hydrocyclone, a separator that applies anelectrostatic field, and a separator that applies microwave treatment.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the features of the present invention can bebetter understood, certain drawings, charts and flow charts are appendedhereto. It is to be noted, however, that the drawings illustrate onlyselected embodiments of the inventions and are therefore not to beconsidered limiting of scope, for the inventions may admit to otherequally effective embodiments and applications.

FIG. 1 presents a flow chart demonstrating a method of separating oiland water, in one embodiment.

FIG. 2 provides a pictorial representation of one process by which theinteraction between fine solids and crude oil polars results indecreased coalescence of water from oil.

FIG. 3 provides a pictorial representation of one process by which apolymeric flocculant binds the solids and the solids-crude oil polarcomplexes into flocculated solids, allowing for increased coalescence ofwater from oil.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS Definitions

As used herein, the term “demulsification” refers to an action by ademulsifier to attract water droplets, and bring them together. Theterms “demulsifier” means any surface active agent that acts to separatewater from oil, and to cause water droplets to be attracted to oneanother.

The terms “emulsion” and “oil/water emulsion” mean either a water-in-oilemulsion or an oil-in-water emulsion.

“Surface facility” means any facility configured to receive productionfluids. The facility may be at or near the wellhead, or may bedownstream. The facility may be on land, on a floating platform, or on avessel.

“Hydrocarbons” are organic material with molecular structures containingcarbon and hydrogen. Hydrocarbons may also include other elements, suchas, but not limited to, halogens, metallic elements, nitrogen, oxygen,and/or sulfur.

“Oil” means a fluid containing a mixture of condensable hydrocarbons.

The term “heavy oil” refers to viscous hydrocarbon fluids, having aviscosity generally greater than about 100 centipoise at ambientconditions (115° C. and 1 atmosphere (atm) of pressure). Heavy oilgenerally has American Petroleum Institute (API) gravity below about 20°and most commonly about 10° to 20°. Heavy oil may include carbon andhydrogen, as well as smaller concentrations of sulfur, oxygen, andnitrogen. Heavy oil may also include aromatics or other complex ringhydrocarbons.

The terms “flocculant” or “flocculating agent” mean a compound thatattracts solid particles and aggregates the solids to prevent dispersionwithin an emulsion.

The terms “production fluids” or “produced fluids” refer to fluidsproduced from a hydrocarbon-bearing formation. Such fluids may carrysolid materials, and may include fluids and solids previously injectedduring drilling or well treatment. Such fluids may or may not containorganic acids, such as asphaltenes.

The term “bitumen” means any naturally occurring, non-crystalline solidor viscous hydrocarbon material that is substantially soluble in carbondisulfide.

The term “wellbore” refers to a hole in a formation made by drilling orinsertion of a conduit into the formation. A wellbore may have asubstantially circular cross section, or other cross-sectional shapes(e.g., circles, ovals, squares, rectangles, triangles, slits, or otherregular or irregular shapes). As used herein, the terms “well” and“opening,” when referring to an opening in the formation may be usedinterchangeably with the term “wellbore.”

Description of Specific Embodiments

A process for separating a crude oil/water emulsion from a flow ofproduction fluids is provided. The flow of production fluids istypically from the wellbore. FIG. 1 presents a flow chart of a process100 for separating oil and water, in one embodiment. The process 100 isapplicable to any emulsion comprising water and oil, but preferably isused for the water-in-oil emulsions. The process 100 is particularlysuitable where the crude oil is heavy oil. The process 100 is alsoparticularly applicable to production fluids of heavy oil having organicacids such as one or more of asphaltenes, naphthenic acid compounds,resins, basic nitrogen compounds and mixtures thereof.

The process 100 is also preferred for water-in-oil emulsions stabilizedat least in part by solids. When solids are present, they contribute tostabilizing the emulsion. Such emulsions may be referred to assolids-stabilized emulsions. The solids typically range from about 0.01wt. % to about 5.0 wt. % of the well stream, such as a productionstream. The solids, if present in the crude oil, are typically finesolids with diameters from about 0.5 microns to about 100 microns.Examples of solids include fine mineral particles, such as silica andclay. The solids may be other solids introduced during drillingoperation or a well workover procedure. Typically, barium sulfate(BaSO₄) is used in drilling muds, and calcium carbonate (CaCO₃) may beintroduced into the drilling operations in “kill-pills”.

The aqueous phase of the emulsion comprises water. The water mayconstitute “brine,” and may include dissolved inorganic salts ofchloride, sulfates and carbonates of Group I and II elements of the longform of The Periodic Table of Elements. Organic salts can also bepresent in the aqueous phase. The process 100 is effective for crude oilemulsions that include brine.

Referring again to the process of FIG. 1, a wellbore is formed throughthe earth surface, as shown in block 110. The wellbore penetratesthrough various subterranean layers, including a hydrocarbon- orcarbonaceous-bearing formation. The wellbore is completed in at leastone production zone or subsurface reservoir. The process 100 is notlimited by the manner in which the well is completed.

It may be desirable to produce the fluids from the hydrocarbon-bearingformation or reservoir. Accordingly, the production fluids are movedfrom the reservoir and into the wellbore, as shown in block 120.Further, the production fluids are pumped (or otherwise moved) to asurface facility, as represented in block 125.

It has been determined that when solids in the size range of 0.1 micronsto 10 microns are present in crude oils, the polar components of crudeoils, such as asphaltenes and naphthenic acids, tend to adsorb on thesolid particles and form surface active solids-crude oil polarscomplexes. Therefore, as part of the process 100, and in accordance withthe methods disclosed herein, the production fluids are treated with aflocculent. This is as shown in block 130.

The purpose of the flocculation step in block 130 is to flocculate thesolids-crude oil polars complex to larger size particles. The largersize flocculants of the polar complex have less surface area and a lowertendency to aggregate at the oil/water interface. Further, the largersize flocculants enhance the phase separation of the solids out of theemulsion as supported by Stokes settling laws.

FIG. 2 provides a pictorial representation of the process by whichinteraction between fine solids 202 and crude oil polars 204 results indecreased coalescence of water 208 from oil. It is shown in FIG. 2 thatfine solids 202 interact with crude oil polars 204 to form solids-crudeoil polars complexes 206. The complexes 206 reside at the water/oilinterface 210 of a crude oil emulsion. When the surface active complexes206 aggregate at the oil/water interface 210, they form a steric barrier212 to water droplet coalescence. This steric barrier 212 results in adecrease in the efficiency of demulsifiers and oil/water separation. Thesolids 202 are believed to be the main contributor to the observedstability of the emulsions.

To more effectively break down emulsions, it was determined that somedecrease in solids attrition is beneficial. Certain demulsifiers, suchas those comprised of ethyleneoxy-propyleneoxy (EO-PO) polymers as thedemulsifier active ingredient, are known to be effective for crude oilemulsions stabilized by crude oil polars and asphaltenes. However, theyare not as effective for emulsions stabilized by solids-crude oil polarscomplexes 206. Therefore, it was determined that the use of a flocculantin the well stream before addition of a demulsifier may be advantageous.Stated another way, early removal of the surface active species assistsin breaking stable emulsions.

FIG. 3 provides a process of flocculating the emulsion (block 130). Itis shown in FIG. 3 that fine solids 202 interact with crude oil polars204 to again form solids-crude oil polars complexes 206. The complexes206 seek to reside at the water/oil interface (210 of FIG. 2) of a crudeoil emulsion. However, when a flocculant 300 is added, the flocculant300 binds both the solids 202 and the solids-crude oil polars complexes206 into larger flocculated solid particles 302 and complexes 304. Thelarger size flocculent solids 302 of the complex 304 have less surfacearea and a lower tendency to aggregate at the oil/water interface.Further, the larger size of the flocculants 302, 304 enhances the fasterphase separation of the solids 302 out of the emulsion as supported byStokes settling laws. Early removal of the surface active species caninhibit formation of the stable emulsions and, additionally, render morefavorable conditions for the performance of chemical demulsifiers inother demulsification operations at the surface.

The flocculant treatment in block 130 may take place in one of severallocations. First, the flocculation in block 130 may be applied to thewell stream, such as the full well stream, when production fluids arebrought from the wellbore and to the surface in block 125. For treatmentof production fluids at the surface facility, the preferred range ofdosage is between about 5 ppm to about 1,000 ppm based on the weight ofthe produced fluids. More preferably, the concentration is between about200 ppm and about 1,000 ppm based on the weight of the produced fluids.

The flocculation in block 130 may alternatively be performed byinjecting flocculant into the reservoir. In this instance, an injectionline runs down the tubing-casing annulus under sufficient pressure tocause the flocculant to intermingle with reservoir fluids within therock matrix. It is not necessary that the flocculant invade theformation more than a few centimeters. Any greater pressure mayinterfere with the production process.

Finally, the flocculation in block 130 is preferably conducted byinjecting the flocculant into the wellbore. An injection line may be rundown the tubing-casing annulus or in some manner external to theproduction tubing. Alternatively, an injection line may be run internalto the production tubing so long as it does not interfere with downholeequipment, such as valves, pumps and gauges. The injection line may ormay not terminate at total depth. In one aspect, flocculant injectiontakes place at more than one depth of the tubing. In either aspect, theflocculant is injected into the wellbore without pressurizing it in amanner to cause it to invade the surrounding formation.

In either a downhole or surface treatment embodiment, the mode ofdelivery of the flocculant is preferably via an aqueous medium.Alternatively, the flocculant may be incorporated as a solid that isintroduced to the production stream. It is preferable to deliver theflocculant in an aqueous medium to increase surface contact with waterdroplets.

Various flocculating agents may be used in block 130. In one aspect, theflocculating agent is an inorganic salt, such as aluminum sulfate and/orferric chloride. In other aspects, cationic polymers, anionic polymersand mixtures thereof may be used. The concentration of the flocculant ispreferably predetermined in laboratory screening experiments. Theexperiments apply various dosages of the flocculating agent to emulsionshaving the fine solids, e.g., 0.5 micron size silica, clay, BaSO₄ andCaCO₃. Determining an ideal concentration of the flocculant may enhanceperformance. A preferred range of dosage for wellbore injection isbetween about 20 ppm to about 2,000 ppm based on the weight of thedelivery medium. More preferably, the range is from about 100 ppm toabout 2,000 ppm based on the weight of an aqueous medium.

Treatment of the well stream (whether in the wellbore or at the surface)with the flocculating agent cause the flocculant to interact with solidsparticles in such a manner as to aggregate (or flocculate) the solids.Where a subsurface pump is used and where the flocculant is injectedinto the wellbore, it is preferred that the mixing forces experienced bythe pumping of crude oil and water during uplift do not significantlycontribute to solids breaking up into smaller particles. This isundesirable as it causes an increase in the solid particle surface area.Such a process of breaking up is known as solids attrition. Minimizationof mixing forces experienced by the full well stream minimizes solidsattrition and also lower the adsorption rate of the crude oil polarsonto the solids surfaces while favoring solids flocculation.

Downhole injection of the flocculants is preferred to surface treatmentof the produced emulsion. It is believed that the presence of theflocculant downhole not only prevents solids attrition, but actuallycauses the size and amount of aggregated or flocculated solids toincrease during production in block 125. In this respect, the mixingenergy caused by pumping or otherwise bringing the fluids up theproduction string may assist the flocculant in interacting with thesolid particles so as to aggregate or flocculate the solids and increasethe solid particle size.

After reaching the surface, the flocculant-treated fluid is directed toa first oil/water separator (i.e. first separator). This separator ispreferably a conventional mechanical separator, such as an electrostaticor cyclone separator. Alternatively, a gravity settler, centrifugation,or microwave separator may be utilized. The first separator separates atleast some of the water and flocculated solids from the crude oil, asshown in block 140. In one embodiment, the operating temperature of thefirst separator is between about 25° C. and about 70° C., or betweenabout 40° C. and about 70° C.

At block 150, the oil emerging from the first separator is next treatedwith a demulsifier. The demulsification in block 150 causes watermolecules entrained or dispersed in oil to coalesce and form largerwater droplets. The demulsifier is added to the emulsion either as itexits the first separator, or within the chamber of a second separator.The use of the second separator for the separated crude oil isrepresented in block 155. The removal of the solids-polar complexes inblock 130 and the removal of the solids in the first separator (block140) provide a more favorable condition for the demulsifier (block 150)to effect oil/water separation.

Demulsifiers utilized in the present techniques may be any demulsifierused in oil/water demulsification. Particularly preferred demulsifiersare those comprised of ethyleneoxy-propyleneoxy (EO-PO) polymers as thedemulsifier active ingredient. Such EO-PO polymeric demulsifiers areknown to be effective for crude oil emulsions stabilized by crude oilpolars and asphaltenes. However, they are not as effective for emulsionsstabilized by solids-crude oil polars complexes.

Another chemical demulsifier that may be employed is aphenolformaldehyde ethoxylated alcohol having the chemical structure:

wherein:

R is selected from the group consisting of alkanes or alkenes from 8 to20 carbons,

E is CH₂—CH₂,

P is CH₂-CH—CH₃,

n ranges from 1 to 5,

m ranges from 0 to 5, and

x ranges from 3 to 9.

The amount of demulsifier to be used ranges from about 0.1 wt. % toabout 5.0 wt. % based on the amount of the crude oil. Additionally, adelivery solvent may be employed. Such solvents may include crude oildistillates boiling in the range of about 70° C. to about 450° C.Solvents may also include alcohols, ethers and mixtures thereof. Thedelivery solvent is present in an amount of from about 35 wt. % to about75 wt. % in the demulsifier. Thus, when utilized, the delivery solventis included in the about 0.1 wt. % to about 5.0 wt. % demulsifier addedto the crude oil-water mixture coming out of the first separator (block140).

The temperature at which the separation process in block 155 isconducted in the second separator may be a variable in the effectivenessof the process. The temperature of operation should preferably be in therange wherein the demulsifier function does not act as a dispersant.Preventing the alteration of function of the demulsifier fromdemulsification to dispersancy through temperature control is one aspectof the disclosed methods. Therefore, it is desirable to conduct thesecond separation in block 155 at a temperature about 15° to about 50°C. lower than the typical temperature of 90° C.

Demulsifiers comprised of the preferred EO-PO polymers exhibit a uniqueinversion of function from demulsification to dispersion with increasein temperature. Such an inversion of function can have a negative impacton separation. Thus, in one embodiment of the invention the performanceinversion temperature of the oil/water emulsion in the presence of thedemulsifier is predetermined and the temperature of separation is chosensuch that it is below the inversion temperature. Preferably, the secondseparation is in the temperature range wherein the temperature is belowthe demulsifier performance inversion temperature. More preferably, thesecond separation (block 155) is at a temperature between about 25° C.and about 70° C., or between about 50° C. and about 70° C. Further, theoperating temperature of the second separator may be about 15° C. toabout 50° C. below an operating temperature of the first separator.

Following demulsifier treatment in block 150 and second water separationin block 155, the separated crude oil may be subjected to one or moreadditional separation methods. This further separation step isrepresented in block 160. Such separation methods for block 160 may beany methods known in the art, including centrifugation, gravitysettling, hydrocyclones, application of an electrostatic field,microwave treatment or combinations thereof. Any other methods known tothe skilled artisan for phase separation may be employed.

Where centrifugation separation is utilized, centrifugation can beconducted at a relative centrifugal force of 500 to 150,000 g(acceleration due to gravity) for about 0.1 hour to about 6 hours ormore. Where application of an electrostatic field is provided, theapplication is preferably about 500-5,000 volts/inch for about 0.1 hourto about 24 hours or more. An electrostatic separator may optionally beused to achieve further separation of water from oil. The thirdseparator process in block 160 may be conducted at temperatures of thewater-in-oil emulsion of about 20° C. to about 200° C. and at pressuresfrom ambient to about 200 psig (about 1480.4 kPa).

After separation in blocks 140, 155, and 160, the oil may be recoveredas a separate phase and delivered into a pipeline or storage facilityfor future transportation, refining, or sale.

EXPERIMENTAL

Laboratory experiments were conducted to demonstrate demulsificationeffectiveness of flocculant-demulsifier treatment to separate crudeoil-water mixtures.

Example 1 Demulsifier Only Treatment

An emulsion sample (referred to as Sample #1) was made by mixing in aSilverson mixer at 1,000 revolutions per minute (rpm):

75 grams of Gryphon crude oil,

6 milliliter (ml) of water,

0.03 grams BaSO₄,

0.03 grams CaCO₃, and

0.01 grams bentonite clay.

Thereafter, Pluronic®-F127 was added to the emulsion. Pluronic®-F127 isan ethoxylated propoxylated alcohol demulsifier manufactured by BASFCorporation. The demulsifier was mixed into the emulsion at 200 rpm andsubjected to electrostatic demulsification. The treat rate for thedemulsifier (0.0075 grams) was 0.01 wt. % of actives based on the weightof the emulsion. Electrostatic demulsification was then conducted at 70°C. and 830 volts/inch potential for 30 minutes using a laboratoryelectrostatic coalescer. The amount of water separated out of the Sample#1 emulsion was 8.3% by weight.

Example 2 Flocculant Plus Demulsifier Treatment

An emulsion sample (referred to as Sample #2) was made by mixing in aSilverson mixer at 1,000 rpm:

75 grams (g) of Gryphon Crude oil,

6 ml of water,

0.03 grams BaSO₄,

0.03 grams CaCO₃,

0.01 g bentonite clay, and

Tramfloc-364 flocculant (cationic polyacrylamide).

The treat rate for the flocculant was (0.0075 grams) at 0.01 wt. % basedon the weight of the emulsion. Thereafter, Pluronic®-F127 demulsifierwas added to the emulsion and mixed at 200 rpm. The treat rate for thedemulsifier (0.0075 grams) was 0.01 wt. % of actives based on the weightof the oil. The emulsion was also subjected to electrostaticdemulsification. Electrostatic demulsification was conducted at 70° C.and 830 volts/inch potential for 30 minutes using a laboratoryelectrostatic coalescer. The amount of water separated out of theemulsion of Sample #2 was 83% by weight.

As can be seen, the amount of water separated from Sample #2 is muchgreater than that separated from Sample #1, even up to ten-fold.Therefore, it can be concluded that by first treating an emulsion with aflocculant followed by the demulsifier, the demulsification performanceis improved.

Example 3 Field Example from an Offshore Oil Field

Example 3 relates to emulsion problems encountered in the offshoreoperations. During 2005, emulsion problems appeared at a productionfacility in an offshore oil field. Two large parallel electrostaticcoalescers in place at the production facility failed to separate waterfrom produced crude oil. This resulted in curtailed production to aterminal.

External scanning of the coalescers was conducted to determine theinternal state of the equipment. Scanning revealed that mud and sludge(“contaminated” sand) had deposited on the bottom of vessels and onelectrodes. The coalescers were cleaned using high pressure flushing. Asa result, 39 cubic meters (m³) of sludge and materials was removed fromthe vessels to place the coalescers back on line and in accordance withthe exportation specifications (including less than 0.5% water).Further, additional jetting nozzles were installed in the coalescers andperiodic jetting routines were established.

In addition, laboratory work was initiated to help in understandingemulsion formation and treatment. Analysis of the emulsion layer in thecoalescers demonstrated the presence of BaSO₄, CaCO₃, silica (SiO₂), andtraces of clay. Particles were in relatively small amounts (less than0.1%), and the size was generally less than 0.5 micrometers.Furthermore, the chemical treatment process was reviewed with a goal todetermine the impact of naphthenic acids on emulsion stabilization, theimpact of particulates size and makeup on emulsion stability, and theappropriateness of emulsifiers for successful treatment of the emulsion.

It was determined that the primary contributor to the emulsion formationand stability in the produced full well stream at the productionfacility was the presence of fine solids. Drilling mud solids aresignificantly larger in size (>100 microns) than the observed 0.5 micronaverage diameter of the solids in the produced full well stream. Thisindicated that the BaSO₄ and CaCO₃ solids remaining in the wellbore hadundergone significant attrition due to the shearing forces experiencedduring production operations. The shearing activity most likely wasexperienced in the wellbore during pumping, although some shearing mayhave taken place during injection through the drilling assembly duringwellbore formation.

The chemical composition of the produced oil also indicated the presenceof polar components, i.e., naphthenic acids and resins and relativelysmall amounts of asphaltenic compounds. It was not believed that thecrude oil polar species by themselves contribute to the stability of thecrude emulsions. However, the adsorption of the resins and naphthenicacids onto the surfaces of the solids renders significant surfaceactivity to the solids, thus causing the emulsion to stabilize.

To break down the emulsions, it was determined that a decrease in solidsattrition is beneficial. The use of a flocculant in the well streambefore addition of a demulsifier is advantageous. Early removal of thesurface active species further assists in breaking stable emulsions.

As discussed above, processes have been disclosed for effectivelyseparating water from oil water emulsions. The disclosed process 100 isparticularly useful when the well stream contains a water-in-oilemulsion that is stabilized with fine solids, as is found in some heavyoil production. The use of a flocculant in the well stream beforeaddition of a demulsifier assists in later demulsification. Thereduction of the fine mineral solids and solids-crude oil polarscomplexes increases the effectiveness of later water separation, andalso enables the second separator 155 to operate at a lower temperaturerange, that is, lower than the more common range of 90° C. used intypical oil/water separators. Laboratory experiments examining theeffect of temperature on solids flocculation and demulsificationeffectiveness can further aid in determining an optimum temperature foroperation of each separator. While it will be apparent that theinvention herein described is calculated to achieve the benefits andadvantages set forth above, it will be appreciated that the invention issusceptible to modification, variation and change without departing fromthe spirit thereof.

1. A process for the separation of production fluids comprising anoil/water emulsion having stabilizing solids comprising: subjecting anoil/water emulsion to a flocculating agent to flocculate solids withinthe oil/water emulsion; separating water and solids in the oil/wateremulsion from crude oil in a first separator; subjecting the separatedcrude oil to a demulsifier after subjecting the oil/water emulsion tothe flocculating agent; and separating additional water from crude oilin a second separator located at a surface facility.
 2. The process ofclaim 1, wherein an operating temperature of the second separator isbetween about 25° C. and about 70° C.
 3. The process of claim 1, whereinan operating temperature of the second separator is between about 50° C.and about 70° C.
 4. The process of claim 1, wherein an operatingtemperature of the second separator is about 15° C. to about 50° C.below an operating temperature of the first separator.
 5. The process ofclaim 1, wherein an operating temperature of the first separator is fromabout 25° C. to about 50° C.
 6. The process of claim 1, wherein:subjecting the oil/water emulsion to the flocculating agent is conductedby injecting the flocculating agent into a wellbore; and separatingwater and solids from crude oil in the first separator is conducted atthe surface facility.
 7. The process of claim 6, wherein subjecting theoil/water emulsion to the flocculating agent is conducted by injectingthe flocculating agent into a region of a hydrocarbon-bearing reservoirnear the wellbore.
 8. The process of claim 6, wherein: the flocculatingagent is delivered by an aqueous delivery medium; and the dosage offlocculating agent delivered into the wellbore is between about 20 partsper million (ppm) to about 2,000 ppm based on the weight of the aqueousdelivery medium.
 9. The process of claim 1, wherein: subjecting theoil/water emulsion to the flocculating agent is conducted by mixing theflocculating agent with the oil/water emulsion at the surface facility;and separating water and solids from crude oil in the first separator isconducted at the surface facility.
 10. The process of claim 1, whereinsubjecting the separated crude oil to the demulsifier comprises mixingthe demulsifier into the separated crude oil before the separated crudeoil enters the second separator.
 11. The process of claim 1, whereinsubjecting the separated crude oil to the demulsifier comprises mixingthe demulsifier into the separated crude oil within the secondseparator.
 12. The process of claim 1, wherein the flocculating agent isan inorganic salt.
 13. The process of claim 1, wherein the flocculatingagent is one of aluminum sulfate, ferric chloride and any mixturesthereof.
 14. The process of claim 1, wherein the flocculating agent isone of a cationic polymer, an anionic polymer and any mixtures thereof.15. The process of claim 1, wherein the flocculating agent is deliveredby an aqueous delivery medium.
 16. The process of claim 15, wherein:subjecting the oil/water emulsion to the flocculating agent is conductedby mixing the flocculating agent with the oil/water emulsion at thesurface facility; and the dosage of flocculating agent is between about5 parts per million (ppm) to about 1,000 ppm based on the weight of theoil/water emulsion.
 17. The process of claim 1, wherein the demulsifieris comprised of one or more ethyleneoxy-propyleneoxy polymers as ademulsifier active ingredient.
 18. The process of claim 17, wherein thedemulsifier is selected from ethoxylated-propoxylated phenolformaldehyderesins and ethoxylated-propoxylated alcohols.
 19. The process of claim18, wherein the demulsifier is in the range from about 0.1 weightpercent (wt. %) to about 5.0 wt. % based on the amount of the separatedcrude oil.
 20. The process of claim 19, wherein a delivery solvent ismixed with the demulsifier before treating the separated crude oil. 21.The process of claim 20, wherein the delivery solvent comprises crudeoil distillates boiling in the range of about 70° C. to about 450° C.22. The process of claim 20, wherein the delivery solvent is selectedfrom the group consisting of crude oil distillates, alcohols, ethers, ormixtures thereof.
 23. The process of claim 20, wherein the deliverysolvent is present in an amount of from about 35 wt. % to about 75 wt. %in the demulsifier, such weight percentage being included in the about0.1 weight percent (wt. %) to about 5.0 wt. % demulsifier added to theseparated crude oil.
 24. The process of claim 20, wherein subjecting theseparated crude oil to the demulsifier comprises mixing the demulsifierinto the separated crude oil upon exiting the first separator.
 25. Theprocess of claim 1, wherein the operating pressure of the secondseparator is between ambient pressure and about 200 pounds per squareinch gauge (about 1480.4 kilo Pascal).
 26. The process of claim 1,wherein the stabilizing solids comprise at least one of formation fines,drilling muds and completion fluids.
 27. The process of claim 26,wherein the solids comprise from about 0.01 weight percent (wt. %) toabout 5.0 wt. % of the oil/water emulsion.
 28. The process of claim 26,wherein the solids comprise fine solids with diameters from about 0.5microns to about 100 microns.
 29. The process of claim 26, wherein thesolids comprise at least one of silica and clay.
 30. The process ofclaim 26, wherein the solids comprise BaSO₄ or CaCO₃ introduced duringan earlier drilling or workover operation.
 31. The process of claim 1,wherein the first separator comprises at least one of a centrifugationseparator, a gravity settling separator, a hydrocyclone, a separatorthat applies an electrostatic field, and a separator that appliesmicrowave treatment.
 32. The process of claim 1, further comprisingprocessing the crude oil released from the second separator through athird separator.
 33. The process of claim 32, wherein the thirdseparator comprises at least one of a centrifugation separator, agravity settling separator, a hydrocyclone, a separator that applies anelectrostatic field, and a separator that applies microwave treatment.34. The process of claim 1, wherein the oil/water emulsion containsdissolved inorganic salts of chloride, sulfates or carbonates of Group Iand II elements of the long form of The Periodic Table of Elements. 35.The process of claim 1, wherein the oil/water emulsion is a water-in-oilemulsion.
 36. The process of claim 35, wherein the crude oil is heavycrude oil.
 37. The process of claim 36, wherein the oil/water emulsionalso comprises one or more of asphaltenes, naphthenic acid compounds,resins, and mixtures thereof.
 38. A process for producing fluids from ahydrocarbon-bearing reservoir comprising: moving production fluids froma hydrocarbon-bearing reservoir into a wellbore and to a surfacefacility, the production fluids comprising a crude oil/water emulsionstabilized at least in part by solids; subjecting the production fluidsto a flocculating agent to flocculate solids within the crude oil/wateremulsion; separating water and solids in the crude oil/water emulsionfrom the crude oil in a first separator; subjecting the separated crudeoil to a demulsifier after the flocculating agent; and separatingadditional water from the separated crude oil in a second separator, thesecond separator operating in a temperature range of between about 25°C. and about 70° C.
 39. The process of claim 38, wherein the operatingtemperature of the second separator is between about 50° C. and about70° C.
 40. The process of claim 38, wherein an operating temperature ofthe second separator is about 15° C. to about 50° C. below an operatingtemperature of the first separator.
 41. The process of claim 38, whereinan operating temperature of the first separator is from about 25° C. toabout 50° C.
 42. The process of claim 38, wherein: subjecting the crudeoil/water emulsion to the flocculating agent is conducted by injectingthe flocculating agent into the wellbore; and separating water andsolids from the crude oil in the first separator is conducted at thesurface facility.
 43. The process of claim 42, wherein: the flocculatingagent is delivered by an aqueous delivery medium; and the dosage offlocculating agent delivered into the wellbore is between about 20 partsper million (ppm) to about 2,000 ppm based on the weight of the aqueousdelivery medium.
 44. The process of claim 38, wherein subjecting thecrude oil/water emulsion to the flocculating agent is conducted bymixing the flocculating agent with the crude oil/water emulsion at thesurface facility.
 45. The process of claim 38, wherein subjecting theseparated crude oil to the demulsifier comprises mixing the demulsifierinto the separated crude oil before the separated crude oil enters thesecond separator.
 46. The process of claim 38, wherein the flocculatingagent is an inorganic salt.
 47. The process of claim 38, wherein theflocculating agent is one of a cationic polymer, an anionic polymer andany mixture thereof.
 48. The process of claim 38, wherein theflocculating agent is delivered by an aqueous delivery medium.
 49. Theprocess of claim 48, wherein: subjecting the crude oil/water emulsion tothe flocculating agent is conducted by mixing the flocculating agentwith the crude oil/water emulsion at the surface facility; and thedosage of flocculating agent delivered into the wellbore is betweenabout 5 parts per million (ppm) to about 1,000 ppm based on the weightof the crude oil/water emulsion.
 50. The process of claim 38, whereinthe demulsifier is comprised of one or more ethyleneoxy-propyleneoxy(EO-PO) polymers as a demulsifier active ingredient.
 51. The process ofclaim 50, wherein the demulsifier is in the range from about 0.1 weightpercent (wt. %) to about 5.0 wt. % based on the amount of the separatedcrude oil.
 52. The process of claim 50, wherein a delivery solvent ismixed with the demulsifier.
 53. The process of claim 52, wherein thedelivery solvent is present in an amount from about 35 weight percent(wt. %) to about 75 wt. % in the demulsifier, such weight percentagebeing included in the 0.1 wt. % to 5.0 wt. % demulsifier added to theseparated crude oil.
 54. The process of claim 38, wherein thedemulsifier is selected from ethoxylated-propoxylated phenolformaldehyderesins and ethoxylated-propoxylated alcohols.
 55. The process of claim38, wherein the stabilizing solids comprise at least one of formationfines, drilling muds and completion fluids.
 56. The process of claim 55,wherein the solids comprise fine solids with diameters from about 0.5microns to about 100 microns.
 57. The process of claim 56, wherein thesolids comprise at least one of silica and clay.
 58. The process ofclaim 38, wherein the first separator comprises at least one of acentrifugation separator, a gravity settling separator, a hydrocyclone,a separator that applies an electrostatic field, and a separator thatapplies microwave treatment.
 59. The process of claim 38, furthercomprising processing crude oil released from the second separatorthrough a third separator.
 60. The process of claim 59, wherein thethird separator comprises at least one of a centrifugation separator, agravity settling separator, a hydrocyclone, a separator that applies anelectrostatic field, and a separator that applies microwave treatment.61. The process of claim 38, wherein the crude oil/water emulsioncontains dissolved inorganic salts of chloride, sulfates or carbonatesof Group I and II elements of the long form of The Periodic Table ofElements.
 62. The process of claim 38, wherein the crude oil/wateremulsion is a water-in-oil emulsion.
 63. The process of claim 62,wherein the crude oil is heavy crude oil.
 64. The process of claim 63,wherein the production fluids further comprises one or more ofasphaltenes, naphthenic acid compounds, resins, and mixtures thereof.